Method for increased oil recovery from an oil field

ABSTRACT

A method for increasing oil recovery from an oil reservoir in which method surplus gas streams from a plant for synthesis of higher hydrocarbons from natural gas is injected into the reservoir, is described. The surplus streams from the plant is the tailgas from the synthesis and optionally nitrogen from an air separation unit which delivers oxygen or oxygen enriched air to the plant for synthesis of higher hydrocarbons.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation of application Ser. No. 10/538,417filed Nov. 10, 2005 which is incorporated herein by reference, and whichis a U.S. national stage application of International Application No.PCT/NO2002/000477, filed 13 Dec. 2002, having an InternationalPublication Number of WO 2004/055322 A1 and an International PublicationDate of 1 Jul. 2004.

THE FIELD OF THE INVENTION

The present invention relates to the use of natural gas and air in thedevelopment of industry and oil fields. In particular, the inventionrelates to a method and a plant for integrated production of synthesisgas and air gas for synthesis of higher hydrocarbons and utilizingsurplus streams for injection into an oil reservoir.

THE BACKGROUND OF THE INVENTION

Injection of various gases into an oil reservoir in order to enhance theoil recovery from the reservoir, and to stabilize it, has for a longtime been known and used. Gases such as CO₂, N₂ and natural gas willreduce the surface tension between gas and oil, and thus contribute toboth increased recovery and stabilization of the reservoir.

During enhanced oil recovery operations, a number of techniques areapplied that depend on the nature of the specific field and wells, theirmaturity, seasonal variations etc. The most common approaches aresecondary oil depletion using water flooding or gas injection. Furtheralternatives, often referred to as tertiary depletion, include injectionof gas after water, alternating gas and water injection (WAG), andsimultaneous water and gas injection (SWAG). Thermal treatment byinjection of steam or in situ combustion is also possible. By gas wehere mean all viable options like methane, other hydrocarbons, nitrogen,air, flue gas, carbon dioxide or mixtures of any of these gases.

Natural gas as such may be injected into fields where the gas does nothave a net value that exceeds the excess profits of increasing the oilrecovery in the field. An oil field contains hydrocarbon liquids (oil),associated gas and water.

N₂ maybe produced together with 02 in a so-called air separation unit(ASU). In an oil field, such an air separation unit will normallyproduce N2 with a purity of >99.9% and oxygen-enriched air. There islittle or no need for this oxygen-enriched air on the oil field, and allor most of this is therefore released.

Separation of air into an “oxygen-depleted stream” and an“oxygen-enriched stream” is 35 described in U.S. Pat. Nos. 5,388,645 and6,119,778. The oxygen-depleted stream is used for injection into a“solid carbonaceous formation” for improved recovery of methane, and atleast a part of the oxygen-enriched stream is used for reaction with areactant stream containing at least one oxidizable reactant. Examples ofprocesses are steelmaking operations, production of non-ferrous metals,chemical oxidation processes and production of synthesis gas forFischer-Tropsch synthesis of higher hydrocarbons from natural gas.

The oxygen-depleted stream has a nitrogen to oxygen volume ratio of 9:1to 99:1. A too low ratio may lead to the formation of an explosive gas.An oxygen-depleted gas, e.g. nitrogen, for injection into an oil fieldto enhance the production preferably includes less than 0.1% oxygen.

No other integration between the processes using the oxygen-depleted andoxygen-enriched streams is mentioned in U.S. Pat. Nos. 5,388,645 or6,119,778.

Natural gas may also be used as feed for a number of processes such asthe production of methanol, di-methyl ether or other oxygenatedhydrocarbons, and/or synthetic fuel/propellant. This can take place inaccordance with known processes such as described in PCT/N000/00404.

The oxygen needed for production of synthesis gas (“syngas”) in plantsfor synthesis of 20 methanol and other oxygenated hydrocarbons and/orsynthetic fuel may be supplied as straight air containing about 21% O₂,oxygenated air containing more than 21% O₂ to pure oxygen of almost100%.

Syngas is a mixture of CO, CO₂, H₂, N₂ and water vapour and some nonreacted natural gas. The syngas is used in various synthesis reactions,such as for the production of methanol and other oxygenatedhydrocarbons, heavier hydrocarbons and ammonia. The N₂ in the syngasenters the system as a part of the natural gas and/or air or oxygenatedair. Nitrogen is inert both in the syngas production and in thedifferent following synthesis reactions and finds its way into thetailgas stream which is then passed through a tailgas combustion unit toproduce power. It is often preferred to use oxygenated air or pureoxygen for the production of syngas to reduce the total gas volume ofthe gas circulating in the plant.

The oxygen produced in an air separation unit in such a plant istypically >95% pure oxygen, while the nitrogen often will be relativelyimpure that is not suitable for other applications, and is thereforereleased to the atmosphere.

A process for preparation of higher hydrocarbons and for enhancing theproduction of crude oil from an underground formation is described inCanadian Patent No. 1,250,863. The off-gas from the synthesis plant isoxidized into mainly CO₂ and H₂O before it is injected into theunderground formation. Preferably, the presence of nitrogen is avoidedby using oxygen from an air separation unit for all oxygen-demandingprocesses.

A SUMMARY OF THE INVENTION

According to a first aspect of the present invention, there is provideda method for increasing oil recovery from an oil reservoir in whichmethod gas is injected into the reservoir, comprising the steps of:

-   -   separating air into an oxygen-rich fraction and a nitrogen-rich        fraction;    -   providing a natural gas stream and leading the natural gas        stream and at least a part of the oxygen-rich fraction to a        reformer for conversion to synthesis gas mainly comprising H₂,        CO, CO₂ and lower amounts of non-converted methane, water vapor        and nitrogen;    -   forming higher hydrocarbons from the synthesis gas in a        synthesis unit;    -   withdrawing raw synthesis products and a waste gas from the        synthesis unit; and    -   injecting the nitrogen rich fraction and at least a part of the        waste gas into the oil reservoir to increase the oil recovery        from the reservoir.

Preferably steam or water generated during the syngas production and/orsynthesis is injected into the reservoir.

According to a second aspect of the present invention, there is provideda plant for providing gas for down-hole injection for pressure supportin an oil reservoir for recovery of hydrocarbons and production ofoxygenated hydrocarbons or higher hydrocarbons from natural gas,comprising:

-   -   an air separation unit for production of an oxygen-rich fraction        for supply to processes that require oxygen, and a nitrogen-rich        fraction for injection;    -   a reformer for conversion of a mixture of natural gas, water and        oxygen or oxygen enriched air from the air separation unit into        a synthesis gas comprising mainly H₂, CO, CO₂ and small amounts        of methane in addition to any inert gas, such as nitrogen;    -   a synthesis unit for conversion of the synthesis gas for        synthesis of higher hydrocarbons;    -   means for injecting gas into the reservoir;    -   means for transferring nitrogen from the air separation unit to        the means for injecting gas; and    -   means for transferring at least a part of a waste gas from the        synthesis unit to the means for injecting gas.

Preferably the plant additionally comprises a tail gas treatment unitfor removing CO by a shift reaction and separation of hydrogen from theremaining tail gas.

Further, the plant preferably comprises means for transferring theremaining tail gas from the tail gas treatment unit to the means forinjecting gas.

The synthesis unit preferably comprises one or more once-throughFischer-Tropsch units for synthesis of higher hydrocarbons.

Additionally the plant preferably comprises means for introducing all orparts of the separated hydrogen from the tail gas treatment unit intothe Fischer Tropsch loop to adjust the H₂/CO ratio to a desired level.

By combining a plant for production of high-purity nitrogen with theproduction of oxygen, the co-producing air separation unit only becomes10-20% more expensive than an air separation unit that only produceshigh-purity nitrogen for injection into oil fields. This allowssignificant cost savings, both for production of synthesis products suchas methanol and synthetic fuel, and for oil field injection.

Additionally, several of these EOR injection fluids or gases are or canbe produced as part of the operation of a GTL plant. The possibilitiesare at least Nitrogen from the ASU unit, as described in detail in thisapplication.

-   -   Flue gas, particularly if traditional SMR (steam methane        reforming) fired heaters and gas turbines are used in whole or        partly.    -   Water produced by the Fischer-Tropsch process. Steam produced by        the FT-process.    -   Light hydrocarbons, including methane, produced by the        FT-process.

According to a third aspect of the present invention, there is provideda method for increasing oil recovery from an oil reservoir in whichmethod gas is injected into the reservoir, comprising the steps ofCompressing pure air,

-   -   providing a natural gas stream and leading the natural gas        stream and at least a part of the air stream to a reformer for        conversion to synthesis gas mainly comprising N₂, H₂, CO, CO₂        and lower amounts of non-converted methane, water vapour,    -   formation of higher hydrocarbons from the synthesis gas in a        synthesis unit,    -   withdrawing raw synthesis products and a nitrogen rich waste gas        from the synthesis unit, and    -   injecting the nitrogen rich waste gas into the oil reservoir to        increase the oil recovery from the reservoir,

Preferably steam or water generated during the syngas production and/orsynthesis is injected into the reservoir.

According to a fourth aspect of the present invention, there is provideda plant for providing gas for down-hole injection for pressure supportin an oil reservoir for recovery of hydrocarbons and production ofoxygenated hydrocarbons or higher hydrocarbons from natural gas,comprising:

-   -   an air compression unit for production of compressed air for        supply to processes that require a pure air stream;    -   a reformer for conversion of a mixture of natural gas, water and        air from the air compression unit into a synthesis gas        comprising mainly N₂,H₂, CO, CO₂ and small amounts of methane;    -   a once-through synthesis unit for conversion of the synthesis        gas for synthesis of higher hydrocarbons;    -   means for injecting gas into the reservoir; and    -   means for transferring at least a part of a nitrogen rich waste        gas from the synthesis unit to the means for injecting gas.

Preferably the plant additionally comprises a tail gas treatment unitfor removing CO by a shift reaction and separation of hydrogen from theremaining tail gas.

Further, the plant preferably comprises means for transferring theremaining tail gas from the tail gas treatment unit to the means forinjecting gas.

The synthesis unit preferably comprises one or more once-throughFischer-Tropsch units for synthesis of higher hydrocarbons.

Additionally the plant preferably comprises means for introducing all orparts of the separated hydrogen from the tail gas treatment unit intothe Fischer Tropsch loop to adjust the H₂/CO ratio to a desired level.

More detailed utilization of some of these possibilities can beillustrated by the examples below. It should be recognized that thereare multiple ways to combine the described injection gases, both bymixing with natural gas, and by applying intermittent operation, alsousing water part of the time.

A BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 shows a schematic diagram of a general embodiment of the presentinvention;

FIG. 2 shows a preferred embodiment of the present invention; and

FIG. 3 shows a schematic diagram of an alternative embodiment of thepresent invention.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 1 is a schematic diagram showing the principal features of ageneral embodiment of the present invention. Air is drawn in through anair intake 1 to an air separation unit 2, where it is separated into themain components nitrogen and oxygen. The air separation unit differsfrom traditional air separation units used for production of oxygen toreformers or for production of nitrogen for injection into an oil well,in that it produces both nitrogen and oxygen with a high purity. Theproduced nitrogen typically has a purity of >99.9%, while the oxygentypically has a purity of 98-99.5%.

The nitrogen is passed through line 3 to a compressor 4 where it iscompressed to the desired pressure, e.g. of the order of 50-400 bar.From the compressor 4, the compressed nitrogen stream is passed througha line 5 to a plant 6 for injection of gas into a field, a so-called EORunit (“Enhanced Oil Recovery”).

The oxygen is passed through a line 7 to a synthesis gas productionemit, a so-called reformer 8.

Natural gas is fed to the plant through a gas inlet 9. Prior to thenatural gas being sent into line 11 to the reformer for production ofsynthesis gas, it is treated in a pre-treatment unit 10 in which sulphurcompounds are removed in a conventional manner. Steam is then saturatedinto the gas and/or added directly to the gas. The saturation may takeplace by means of a so-called saturator. Often, the gas is also treatedin a so-called pre-reformer in order to convert all heavier hydrocarbons(C2+) to methane, CO and CO₂ before the gas is sent into the reformer 8.

In the reformer, the following are the main chemical reactions to takeplace during the production of synthesis gas:

-   1. CH₄ ⁺H₂O═CO+3H₂, steam reforming-   2. CH₄+3/2 02=CO+2H₂O, partial oxidation-   3. CO+H₂O═CO₂+H₂, shift reaction

Reaction 1 in the reforming reactor is highly endothermic, and the heatrequired for the reaction may either be added through external heating,such as in a steam: reformer, or through a combination with internalpartial oxidation according to reaction 2, such as in an autothermalreformer. In a steam reformer (SR), natural gas. (NG) is converted in atubular reactor at a high temperature and relatively low pressure. Aconventional steam reformer consists of a large number of reactor tubesin a combustion chamber. Conventional steam reformers are operated in apressure range from approximately 15 to 40 bar. The outlet temperaturefor such a reformer can get up to 950° C. The heat required to drive thereaction is added by means of external heating in the combustion chamberin which the reformer tubes are installed.

The reformer may be top, bottom or terrace fired. The heat can also betransferred to the reaction by means of convective heat as in a heatexchanger reactor. The ratio between steam and carbon in the feed gas isfrom 1.6 to 4. The composition of the synthesis gas may as an example beexpressed by the stoichiometric number SN(H₂—CO₂)/(CO₂+CO). Thestoichiometric number for the product stream from the steam reformer isapproximately 3 when the natural gas contains pure methane. A typicalsynthesis gas from a conventional steam reformer contains approximately3 volume % methane on dry gas basis.

In an autothermal reformer (ATR), the synthesis gas production mainlytakes place through reactions 1 and 2, such that the heat required forreaction 1 is generated internally via reaction 2. In an ATR, naturalgas (methane) is led into a combustion chamber together with anoxygen-containing gas such as air. The temperature of the combustionchamber can get up to over 2000° C. After the combustion, the reactionsare brought to an equilibrium across a catalyst before the gases leavethe reformer at a temperature of approximately 1000° C. Thestoichiometric number, SN, for the product stream from an ATR isapproximately 1.6-1.8. The pressure may typically be around 30-40 bar,but a significantly higher pressure has also been proposed, such as inthe range of 40-120 bar. The steam/carbon ratio may vary with theintended application, from 0.2 to 2.5.

An alternative autothermal reformer makes use of a concept calledpartial oxidation (PDX). Such a reformer does not contain any catalystfor accelerating the reactions, and will therefore generally have ahigher outlet temperature than an ATR.

Natural gas reforming may also take place through combined reforming(CR), where the reformer section consists of a SR and an ATR. Acombination of SR and ATR allows the composition exiting the reformersection to be adjusted by regulating the duties of the two reformers. SRwill in CR be operated under milder conditions than in the case ofnormal SR, i.e. at a lower temperature. This results in a higher methaneslippage in the outlet gas from the reformer. This methane content isconverted to synthesis gas in the subsequent ATR The Ratio between steamand carbon in the gas feed will, for such a reformer, lie in the range1.2 to 2.4, with a stoichiometric number, SN, of around 2 or slightlyabove 2.

The desired composition of the synthesis gas will depend on the processconditions. The desired stoichiometric number for production ofsynthetic fuel often lies in the range 1.6 to 1.9, as a higherstoichiometric number gives a greater yield of lighter hydrocarbons thandesirable.

After reforming, the synthesis gas is cooled by being heal exchangedwith water to give steam. Upon further cooling, water is condensed andseparated from the synthesis gas before the synthesis gas is sent via aline 12 to a synthesis unit 15.

The synthesis unit 15 may for instance be a synthesis unit forproduction of synthetic fuel (heavier hydrocarbons), comprising aso-called Fischer-Tropsch reactor (F-T reactor).

The reaction may be described using the following reaction equation:nCO+2nH₂=[—CH₂—]_(n) +nH₂O

The reaction is highly exothermic. The Fischer-Tropsch synthesis is wellknown and is described e.g. in PCT/N000/00404.

The process normally includes internal recycling of non-reactedsynthesis gas in order to increase the carbon-efficiency of the process.

The product from the synthesis unit 15 is extracted through a productoutlet 16 for further treatment. Non reacted synthesis gas and inert gasthat collects in the loop can be removed from the-synthesis unit 15through line 17. This gas will in the following description be denotedthe waste gas from the synthesis unit. The amount and composition of thewaste gas from the synthesis unit depends on the released methane in thesynthesis gas from the reformer section, as well as selected processparameters in the synthesis unit.

If CO₂ is required for injection into the oil well in addition tonitrogen, or if environmental conditions require the emission of CO₂from the plant to be reduced, the waste gas from the synthesis unit mayalternatively be further passed to a CO shift converter 18 in which COis converted according to the following reaction equation:CO+H₂O→CO₂+H₂in order to make it easier to separate out the carbon content of thegas.

When the synthesis unit 15 is a synthesis unit for production ofsynthetic fuel, synfuel, it may also be desirable to recycle non-reactedsynthesis gas from line 17 to the reformer via line 26.

By recycling via line 26, the H₂/CO ratio of the synthesis gas may beadjusted to the desired value, i.e. around 2.0 or just below 2.0, andthe CO yield and thereby also synthetic fuel yield may be increased bythe high content of CO₂ in the recycling gas suppressing furtherconversion of CO to CO₂ through the shift reaction in the autothermalreformer. Here, it should be noted that CO₂ is to be considered as aninert gas in the F-T synthesis.

If the reformer produces more synthesis gas than can be converted in thesynthesis unit, some of the synthesis gas may be led from a line 14running between the CO₂ recovery unit 13 and the synthesis unit 15, andaround the synthesis unit in a bypass line 25. This may also bedesirable if there is a wish to produce more heat or power in a furnaceor gas turbine 23.

In certain cases it may also be desirable to remove a volume of nitrogenfrom line 5 out into a line 27 and bring this together with the gas inline 22, which is led to a gas turbine in unit 23 in order to controlthe combustion and generation of heat in this.

The units 13 and 20 for separating CO₂ from the remainder of the gas areknown units. By the reformer 3 being supplied with pure oxygen insteadof air, the volume of gas to be treated becomes considerably smaller.The separation in the units 13, 20 may take place in a known manner bymeans of semi-permeable membranes or by absorption with subsequentdesorption, e.g. in an amine solution.

The air separation unit 2 is preferably: a plant based on cryogenicdistillation, however it is also possible to use plants based onpressure swing adsorption or membranes or a combination of thesetechnologies.

FIG. 2 illustrates a preferred embodiment of the present inventionwherein the synthesis unit is a once-through Fischer-Tropsch system forsynthesis of higher hydrocarbons from natural gas. Units having the samereference numbers as in FIG. 1, indicate units having the samefunctionality.

Natural gas from the gas inlet 9 is saturated and pre-reformed in thepre-treatment unit 10. Steam for the pre-treatment is added through asteam line 50. The pre-treated natural gas is passed from thepre-treatment unit 10 to the reformer 8, for production of syngas,through line 11. Oxygen from the air separation unit (ASU) 2 isintroduced into the reformer 8 through line 7. Nitrogen from the ASU 2is passed through line 3 to the plant for injection (EOR)₆.

The reformer 8 is a traditional steam methane reformer (SMR) or anautothennal reformer 5 (ATR) and may include one or more units forsyngas production and/or separation of the produced syngas. Syngasproduced in the reformer 8 is passed through line 12 to a syngascool-down unit 52. All or a part of the flue gas from the reformer 8,mainly comprising CO₂ and H₂O, may be separated from the syngas and ledto the EOR 6 through a line 51. The line 51 is dotted to indicate thatthe line 51 is not obligatory. lithe reformer 8 is a ATR unit there willbe no flue gas and no line 51.

In the syngas cool-down unit 52, water is introduced through line 53 andsteam is withdrawn through a line 54. The steam in line 54 may be led tothe EOR for injection into the oil reservoir. If some or all of thesteam in line 54 is not needed for injection, some or all of the steamin line 54 may be used for other purposes. Some of the steam may betransferred to line 50 and be introduced to the pre-treatment unit 10.Alternatively, the steam may be utilised in a not shown turbine togenerate power for other uses.

The cooled-down syngas leaves the cool-down unit 52 through a line 42and is passed through 20 a membrane unit 43 where hydrogen is separatedfrom the syngas to give an H₂/CO ratio that is useful for the furtherreactions.

The decant water separated from the syngas is led through line 49 to theEOR 6, and hydrogen is withdrawn through line 48 and can be used as fuelgas or for feed gas desulfurization or hydrotreating/hydrocracking ofoils fractions. The syngas leaving the membrane unit 43 through a line44 is introduced into a Fischer-Tropsch (FT) synthesis loop 56 forproduction for higher hydrocarbons. Higher hydrocarbons in the presentdescription are hydrocarbon molecules having three or more carbon atoms,more preferably five or more carbon atoms.

Further background on FT synthesis may be found in WO/01/42175 toStatoil ASA, and the prior art cited therein.

Raw higher hydrocarbon product from the FT synthesis loop 56 iswithdrawn through a line 57, and the produced water is withdrawn througha line 58 and passed to the EOR 6.

The remaining gas (tail gas) mainly comprising CO₂. lower hydrocarbons,H₂O, CO and some nitrogen, is withdrawn through a line 62.

The tail gas in line 62 is introduced to a tail gas treatment unit 63,in which CO is removed by a shift reaction (CO+H₂O→CO₂+H₂). Theremaining tail gas is split into a hydrogen rich stream that iswithdrawn through a line 64, and a hydrogen poor fraction that iswithdrawn through a line 65.

The hydrogen in line 64 may be used for other reactions requiringhydrogen and/or be introduced into the Fischer-Tropsch loop 56 to adjustthe H2/CO-ratio in the syngas.

The remaining tail gas, or the hydrogen-poor fraction, in line 65 may besplit into two streams, one in a line 59 that is introduced to the EORand another stream in a line 45 that is used as fuel for a powergeneration unit 46. The tail gas introduced into the power generationunit 46 is burned in the presence of air or oxygen-enriched air toproduce power or heat. Flue gas from the power generation unit 46 is ledthrough a line 47 to the EOR 6 for injection.

The great advantage of the present method and plant is that they allowsimple and energy efficient operation of the combined plant

The present invention, in its different embodiments, also makes itpossible to customize the plant and respectively alter the workingconditions according to the specific need and/or variations ineconomical and technical factors. Some advantages of using theembodiment according to FIG. 2 are listed below:

-   -   Water Injection.    -   Water or steam are generated several places in the GTL plant.        First, it should be recognized that steam is generated at        elevated pressures and temperatures. In particular, the elevated        pressure will be an advantage for EOR, as work for compression        to the desired injection pressure will be reduced. Often the        energy content of the steam is utilized in a steam turbine to        produce electricity or for heat input to process units like        distillation towers, whereby the steam may be condensed to        water.

Water/steam is produced (synthesized) in the FT reactor by the reaction:nCO+2nH2→nH2O+(—CH2-) n

Additionally some water is produced in the autothermal reformer.

In other words, water or steam is synthesized in the same amount on amolar basis as the number of —CH₂ units in the hydrocarbon product. Thiswill be ca. double the amount of oxygen (mole) produced by the ASU, orhalf the amount of nitrogen (excluding oxygen loss to CO₂ in thecalculation). It should also be understood that there is a significantuse of boiler feed water for steam generation in an FT-plant, notably inthe heat exchanger for the FT-reactors themselves and to cool down thesynthesis gas. Furthermore, there is also a significant use of coolingwater in an FT plant. The water generated in the FT reaction willunavoidably contain small amounts of impurities comprising alcohols,acids and other oxygenates that often will have to be removed in costlywater treatment facilities before disposal. This purification may not benecessary if the water is used for EOR.

-   -   Steam Injection    -   As described in Example A, steam is generated in several places        in the GTL plant. As such, this is a valuable product that at        least partly may be used to produce electric power. Particularly        in a remote location, it may be more feasible to use steam for        EOR.

All in all, when water or steam is used for EOR, integration with a GTLplant can have the following benefits:

-   -   Water may not be available from other sources.    -   Water and/or steam is available at an elevated pressure.    -   Steam is available (high pressure and temperature).    -   Purification of the produced water is avoided.    -   Flue Gas Injection    -   Flue gas may essentially come from two sources, either the        exhaust gas from a gas turbine or a fired heater integrated with        the GTL facility, or from application of a steam reformer (SMR)        for production of synthesis gas (in this application also called        waste gas). If flue gas is desirable for EOR, this may give an        advantage for SMR (steam methane reforming) over other syngas        technologies like ATR (autothermal reforming) or GDR (gas heated        reforming). SMR may also be part of the total syngas generation        option, like in combined reforming or tail gas reforming.

Injection of FT-Tail Gas.

Unless the intention of the EOR operation is simple gravitystabilization, that is, gas compression from top to bottom of the oilreservoir, it frequently is an advantage if the gas has a highmiscibility with the oil. Nitrogen has low miscibility, and methanesomewhat higher, whereas CO₂ and higher hydrocarbons (C2+) are moreeasily mixed with the oil

It is well known that optimization of a GTL plant will comprise recyclestreams, e.g. recycle of the tail gas (light off-gas) from theFT-reactor to the syngas unit or back to the FT-reactor, in order toincrease overall energy and carbon efficiency. This tail gas from theFT-reactor, usually after separation of the main products (C5+) andwater, then will contain CO₂, light hydrocarbons, and unconvertedsyngas. All or part of the tail gas can be used for EOR, possibly aftermixing it with nitrogen, natural gas or CO₂ from a dedicated CO₂separation unit. Now it may be a disadvantage, particularly for moderateconversion in the FT-reactor, that the tail gas contains unconvertedsyngas. One option therefore is to pass the gas through an additionalsyngas conversion unit, like a second FT-reactor, to secure highconversion before EOR Hydrogen may also be removed in a dedicated unit,for instance a polymer membrane separator, and CO converted to CO₂ andhydrogen in a shift reactor.

Using the Fischer-Tropsch tail gas for EOR opens up the possibility fora significant simplification and cost reduction for the GTL plant. Infact, a once-through concept might be feasible. No recycle also opens upthe possibility for a simplified ASU using only enriched air for an ATRsyngas generator. This enriched air may contain 25% nitrogen that willend up in the tail gas and thereby the EOR stream.

FIG. 3 illustrates an alternative embodiment of the present inventionwhere the air that is drawn in through air intake 1 is not separated butwhere the air is compressed in a compression unit 24 and before it ispassed through line 7 to the reformer 8. The nitrogen in the air isinert in the reactions in the plant and ends up in the tailgas that isintroduced into the injection plant 6 for injection into the formationin question.

Those skilled in the art will appreciate that there may be units in theabove figures for adjusting the pressure of the gases, such ascompressors or reducing valves that are not shown, but which arenecessary in order to match the pressures of the various units and toensure that the streams flow in the right direction. Moreover, there maybe units for heating or cooling, or heat exchangers that are not shownhere, the function of which is to optimise the energy efficiency of theplant.

In must be understood that for off-shore oil or gas fields, one or allthe processing units described in this application, also can be placedoff-shore, like the entire GTL-plant or only the ASU or the syngassection.

EXAMPLE 1

A simulation on a plant as illustrated in FIG. 2 was performed. 367 000Sm3/hr natural gas from line 9 was mixed with 183 t/h steam from line 50in order to reach a steam-to-carbon ratio of 0.6. The mixture waspreheated to 600° C. and fed to an. auto-thermal reformer (ATR) 8. 275t/hr oxygen (6600 MTPD) was introduced into the ATR 8 from the line 7.The outlet temperature from the ATR 8 was 1030° C. The amount of oxygenconsumed in the ATR corresponds to a co-production of N₂ of 39600 MTPD.

The syngas leaving the ATR 8 through line 12, which is in equilibriumand at a temperature of around 1030° C., is cooled to about 350° C. withevaporating water in the syngas cool-down unit 52 producing about 830t/h saturated 110 bar steam that is withdrawn in line 54. The steam inline 54 may be utilized for EOR as illustrated in FIG. 4, or in turbinesto generate power.

After the syngas has been cooled down 178 t/h decant water is removedand about 60 000 Sm³/hr hydrogen (hydrogen purity of 90%) is separatedin the membrane unit 43 before the syngas is fed to the Fischer-Tropschloop 56. The decant water is withdrawn through line 49 and may be usedfor EOR. The separated hydrogen is withdrawn through line 48.

The Fischer-Tropsch loop produces 233 t/h gas that is withdrawn throughline 65, 138 t/h syncrude (long paraffin chains) that is withdrawnthrough line 57 and 198 t/h water that is withdrawn through line 58.

The syncrude must be farther processed in a way known by the skilled.man in the art, by a not shown hydrotreater, hydrocracker and/or solventde-waxing unit in order to give desired products (LPG, naphtha, dieseland/or lubrication oils).

The water from the Fischer-Tropsch loop that is withdrawn in line 58,contains dissolved impurities (mainly alcohols) and may be transferredto the EOR 6 and be injected into the oil field.

To maximize the amount of CO₂ available for recovery from the gas inline 65, the gas may be shifted with a low-temperature copper catalystto convert about 86% of the CO into CO₂. A CO₂ recovery of 95% will thenimply that 180 t/hr CO₂ is available for EOR purposes from the gas inline 65.

After the CO₂ recovery, there will still be about 830 MW heat available(LHV).

The gas compositions of some key streams are shown in Table 4.

TABLE 4 Composition in key process gas lines Number Line Description NGFeed⁹ Syngas¹² Hydrogen⁴⁸ FT Feed⁴² Total Stream Properties RateKG-MOL/HR  15521.3  56424.8  2566.3  43977.4 Kg/hr 301848.2 761722.813377.3 570334.8 Composition Component Molar Rate KG-MOL/HR H2 0.0000.514 0.906 0.606 CO 0.000 0.238 0.033 0.304 CO2 0.052 0.049 0.052 0.059H2O 0.000 0.178 0.006 0.004 N2 0.027 0.007 0.001 0.009 Methane 0.8370.013 0.001 0.017 Ethane 0.052 0.000 0.000 0.000 Propane 0.032 0.0000.000 0.000

1. A plant for providing gas for down-hole injection for pressuresupport in an oil reservoir for recovery of hydrocarbons and productionof oxygenated hydrocarbons or higher hydrocarbons from natural gas,comprising: an air separation unit for production of an oxygen-richfraction for supply to processes that require oxygen and a nitrogen-richfraction for injection; a reformer for conversion of a mixture ofnatural gas, water and oxygen or oxygen-enriched air from the airseparation unit into a synthesis gas comprising mainly H₂, CO, CO₂ andsmall amounts of methane in addition to any inert gas; a synthesis unitfor conversion of the synthesis gas for synthesis of higherhydrocarbons; means for injecting gas into the reservoir; means fortransferring nitrogen from the air separation unit to the means forinjecting gas; means for transferring at least a part of a waste gasfrom the synthesis unit to the means for injecting gas; means fortransferring steam generated in the plant to the means for injecting gasinto the reservoir; and, a tail gas treatment unit for removing CO by ashift reaction and separation of hydrogen from the remaining tail gas.2. The plant according to claim 1 further comprising means fortransferring the remaining tail gas from the tail gas treatment unit tothe means for injecting gas.
 3. The plant according to claim 2, whereinthe synthesis unit comprises one or more once-through Fischer-Tropschunits for synthesis of higher hydrocarbons.
 4. The plant according toclaim 1, wherein the synthesis unit comprises one or more once-throughFischer-Tropsch units for synthesis of higher hydrocarbons.
 5. The plantaccording to claim 1, wherein a line is provided to transfer steamgenerated in reformer to the means for injecting gas.
 6. A plant forproviding gas for down-hole injection for pressure support in an oilreservoir for recovery of hydrocarbons and production of oxygenatedhydrocarbons or higher hydrocarbons from natural gas, comprising: an aircompression unit for production of compressed air for supply toprocesses that require air; a reformer for conversion of a mixture ofnatural gas, water and oxygen or oxygen-enriched air from the airseparation unit into a synthesis gas comprising mainly N₂, H₂, CO, CO₂and small amounts of methane; a synthesis unit for conversion of thesynthesis gas for synthesis of higher hydrocarbons; means for injectinggas into the reservoir; means for transferring nitrogen from the airseparation unit to the means for injecting gas; means for transferringat least a part of the nitrogen-rich waste gas from the synthesis unitto the means for injecting gas; means for transferring steam generatedin the plant to the means for injecting gas into the reservoir; and, atail gas treatment unit for removing CO by a shift reaction andseparation of hydrogen from the remaining tail gas.
 7. The plantaccording to claim 6, further comprising means for transferring theremaining tail gas from the tail gas treatment unit to the means forinjecting gas.
 8. The plant according to claim 7, wherein the synthesisunit comprises one or more once-through Fischer-Tropsch units forsynthesis of higher hydrocarbons.
 9. The plant according to claim 6,wherein the synthesis unit comprises one or more once-throughFischer-Tropsch units for synthesis of higher hydrocarbons.
 10. Theplant according to claim 6, wherein a steam line is provided to transfersteam generated in a syngas cool down unit to the means for injectinggas.